Oil sand, as known in the Athabasca region of Alberta, Canada, comprises water-wet, coarse sand grains having flecks of a viscous hydrocarbon, known as bitumen, trapped between the sand grains. The water sheaths surrounding the sand grains contain very fine clay particles. Thus, a sample of oil sand, for example, might comprise 70% by weight sand, 14% fines, 5% water and 11% bitumen. (All % values stated in this specification are to be understood to be % by weight.) The bitumen recovered from Athabasca oil sand is generally very viscous and has an API gravity of less than 10 due to the large amount of heavy ends, such as kerosenes and asphaltenes. For a typical oil sand ore bitumen, with a density of 1002 kg/m3 at 20° C., the API gravity is 9.3.
For the past 25 years, the bitumen in Athabasca oil sand has been commercially recovered using a water-based process. In the first step of this process, the oil sand is slurried with process water, naturally entrained air and, optionally, caustic (NaOH). The slurry is mixed, for example in a tumbler or pipeline, for a prescribed retention time, to initiate a preliminary separation or dispersal of the bitumen and solids and to induce air bubbles to contact and aerate the bitumen. This step is referred to as “conditioning”.
The conditioned slurry is then further diluted with flood water and introduced into a large, open-topped, conical-bottomed, cylindrical vessel (termed a primary separation vessel or “PSV”). The diluted slurry is retained in the PSV under quiescent conditions for a prescribed retention period. During this period, aerated bitumen rises and forms a froth layer, which overflows the top lip of the vessel and is conveyed away in a launder. Sand grains sink and are concentrated in the conical bottom. They leave the bottom of the vessel as a wet tailings stream containing a small amount of bitumen. Middlings, a watery mixture containing solids and bitumen, extend between the froth and sand layers.
The wet tailings and middlings are separately withdrawn, combined and sent to a secondary flotation process. This secondary flotation process is commonly carried out in a deep cone vessel wherein air is sparged into the vessel to assist with flotation. This vessel is referred to as the TOR vessel. The bitumen recovered by flotation in the TOR vessel is recycled to the PSV. The middlings from the deep cone vessel are further processed in induced air flotation cells to recover contained bitumen.
The froths produced by the PSV and flotation cells are combined and subjected to cleaning, to reduce water and solids contents so that the bitumen can be further upgraded. More particularly, it has been conventional to dilute this bitumen froth with a light hydrocarbon diluent, for example, with naphtha, to increase the difference in specific gravity between the bitumen and water and to reduce the bitumen viscosity, to thereby aid in the separation of the water and solids from the bitumen. This diluent diluted bitumen froth is commonly referred to as “dilfroth”. It is desirable to “clean” dilfroth, as both the water and solids pose fouling and corrosion problems in upgrading refineries. By way of example, the composition of naphtha-diluted bitumen froth typically might have a naphtha/bitumen ratio of 0.65 and contain 20% water and 7% solids.
Separation of the bitumen from water and solids may be done by treating the dilfroth in a sequence of scroll and disc centrifuges. Alternatively, the dilfroth may be subjected to gravity separation in a series of inclined plate separators (“IPS”) in conjunction with countercurrent solvent extraction using added light hydrocarbon diluent. However, these treatment processes still result in bitumen often containing undesirable amounts of solids and water.
More recently, a staged settling process for cleaning dilfroth was developed as described in U.S. Pat. No. 6,746,599, whereby dilfroth is first subjected to gravity settling in a splitter vessel to produce a splitter overflow (raw dilbit) and a splitter underflow (splitter tails) and then the raw dilbit is further cleaned by gravity settling in a polisher vessel for sufficient time to produce an overflow stream of polished dilbit and an underflow stream of polisher sludge. Residual bitumen present in the splitter tails can be removed by mixing the splitter tails with additional naphtha and subjecting the produced mixture to gravity settling in a scrubber vessel to produce an overhead stream of scrubber hydrocarbons, which stream is recycled back to the splitter vessel. However, the polisher sludge may still contain a substantial amount of bitumen (up to about 15% to about 20% of the total feed bitumen). It is suggested in U.S. Pat. No. 6,746,599 that the polisher sludge may be mixed with the diluted splitter tails prior to feeding the splitter tails to the scrubber vessel in an attempt to capture this remaining bitumen.
The very viscous bitumen produced with any of the above naphtha-based froth treatment processes is generally not suitable for most conventional North American refineries, as it has an API gravity of less than 10, i.e., generally around 8-9, and substantial heavy ends content (e.g., about 15-20% asphaltenes). Thus, most bitumen recovered from oil sands extraction must be upgraded in non-conventional refineries, for example, those that might use coking as a first step in the refining process, since most conventional refineries were designed to process much lighter crude oils. Paraffinic-based froth treatment processes can produce a more suitable dry, lighter bitumen but these processes experience high bitumen losses that can significantly affect overall recoveries, primarily due to asphaltene losses.
Further, the bitumen produced with any of the above naphtha-based froth treatment processes generally does not meet pipeline specifications due to its high API and viscosity.